Solids-stabilized emulsion

ABSTRACT

The disclosed invention is a solids-stabilized emulsion and method for making same for use in recovering hydrocarbons from a subterranean formation. More specifically, the emulsion comprises oil and water and is stabilized using undissolved solid particles, which are preferably at least partially oleophilic. Carbon dioxide or another gas is added to the emulsion to adjust the emulsion&#39;s viscosity to the desired level. The solids-stabilized emulsion may be used either as a drive fluid for displacing hydrocarbons from the formation or to produce a barrier for diverting flow of fluids in the formation. Such solid particles may be either formation solid particles (i.e., indigenous to the formation) or nonformation solid particles (i.e., obtained from outside the formation). Nonformation solid particles may either be naturally occurring or synthetic. Some preferred solids include clays, quartz, feldspar, gypsum, coal dust, asphaltenes, and polymers.

REFERENCE TO RELATED APPLICATIONS

This application is a division of U.S. patent application Ser. No.09/062,167, filed Apr. 17, 1998, now allowed which is acontinuation-in-part of U.S. patent application Ser. No. 08/885,507,filed Jun. 30, 1997, pending which claims the benefit of U.S.Provisional patent application Ser. No. 60/047,620, filed May 23, 1997.

FIELD OF THE INVENTION

The present invention relates to a solids-stabilized emulsion for use inrecovering hydrocarbons from a subterranean formation. The emulsion maybe used either to displace hydrocarbons from the formation or to producea barrier for diverting flow of fluids in the formation. Carbon dioxideor another gas is added to the emulsion to adjust the emulsion'sviscosity to the desired level.

BACKGROUND OF THE INVENTION

Oil recovery is usually inefficient in subterranean formations(hereafter simply referred to as formations) where the mobility of thein situ oil being recovered is significantly less than that of the drivefluid used to displace the oil. Mobility of a fluid phase in a formationis defined by the ratio of the fluid's relative permeability to itsviscosity. For example, when waterflooding is applied to displace veryviscous heavy oil from a formation, the process is very inefficientbecause the oil mobility is much less than the water mobility. The waterquickly channels through the formation to the producing well, bypassingmost of the oil and leaving it unrecovered. In Saskatchewan, Canada,primary production crude has been reported to be about 2 to 8% of theoil in place, with waterflooding yielding only another 2 to 5% of theoil in place. Consequently, there is a need to either make the watermore viscous, or use another drive fluid that will not channel throughthe oil. Because of the large volumes of drive fluid needed, it must beinexpensive and stable under formation flow conditions. Oil displacementis most efficient when the mobility of the drive fluid is significantlyless than the mobility of the oil, so the greatest need is for a methodof generating a low-mobility drive fluid in a cost-effective manner.

Oil recovery can also be affected by extreme variations in rockpermeability, such as when high-permeability "thief zones" betweeninjectors and producers allow most of the injected drive fluid tochannel quickly to producers, leaving oil in other zones relativelyunrecovered. A need exists for a low-cost fluid that can be injectedinto such thief zones (from either injectors or producers) to reducefluid mobility, thus diverting pressure energy into displacing oil fromadjacent lower-permeability zones.

In certain formations, oil recovery can be reduced by coning of eithergas downward or water upward to the interval where oil is beingproduced. Therefore, a need exists for a low-cost injectant that can beused to establish a horizontal "pad" of low mobility fluid to serve as avertical barrier between the oil producing zone and the zone whereconing is originating. Such low mobility fluid would retard verticalconing of gas or water, thereby improving oil production.

For modestly viscous oils--those having viscosities of approximately20-100 centipoise (cp)--water-soluble polymers such as polyacrylamidesor xanthan gum have been used to increase the viscosity of the waterinjected to displace oil from the formation. For example, polyacrylamidewas added to water used to waterflood a 24 cp oil in the Sleepy HollowField, Nebr. Polyacrylamide was also used to viscosify water used toflood a 40 cp oil in the Chateaurenard Field, France. With this process,the polymer is dissolved in the water, increasing its viscosity.

While water-soluble polymers can be used to achieve a favorable mobilitywaterflood for low to modestly viscous oils, usually the process cannoteconomically be applied to achieving a favorable mobility displacementof more viscous oils--those having viscosities of from approximately 100cp or higher. These oils are so viscous that the amount of polymerneeded to achieve a favorable mobility ratio would usually beuneconomic. Further, as known to those skilled in the art, polymerdissolved in water often is desorbed from the drive water onto surfacesof the formation rock, entrapping it and rendering it ineffective forviscosifying the water. This leads to loss of mobility control, poor oilrecovery, and high polymer costs. For these reasons, use of polymerfloods to recover oils in excess of 100 cp is not usually technically oreconomically feasible. Also, performance of many polymers is adverselyaffected by levels of dissolved ions typically found in formations,placing limitations on their use and/or effectiveness.

Water-in-oil macroemulsions have been proposed as a method for producingviscous drive fluids that can maintain effective mobility control whiledisplacing moderately viscous oils. For example, the use of water-in-oiland oil-in-water macroemulsions have been evaluated as drive fluids toimprove oil recovery of viscous oils. Such emulsions have been createdby addition of sodium hydroxide to acidic crude oils from Canada andVenezuela. In this study, the emulsions were stabilized by soap filmscreated by saponification of acidic hydrocarbon components in the crudeoil by sodium hydroxide. These soap films reduced the oil/waterinterfacial tension, acting as surfactants to stabilize the water-in-oilemulsion. It is well known, therefore, that the stability of suchemulsions substantially depends on the use of sodium hydroxide (i.e.,caustic) for producing a soap film to reduce the oil/water interfacialtension.

Various studies on the use of caustic for producing such emulsions havedemonstrated technical feasibility. However, the practical applicationof this process for recovering oil has been limited by the high cost ofthe caustic, likely adsorption of the soap films onto the formation rockleading to gradual breakdown of the emulsion, and the sensitivity of theemulsion viscosity to minor changes in water salinity and water content.For example, because most formations contain water with many dissolvedsolids, emulsions requiring fresh or distilled water often fail toachieve design potential because such low-salinity conditions aredifficult to achieve and maintain within the actual formation. Ionicspecies can be dissolved from the rock and the injected fresh water canmix with higher-salinity resident water, causing breakdown of thelow-tension stabilized emulsion.

Various methods have been used to selectively reduce the permeability ofhigh-permeability "thief" zones in a process generally referred to as"profile modification". Typical agents that have been injected into thereservoir to accomplish a reduction in permeability of contacted zonesinclude polymer gels or cross-linked aldehydes. Polymer gels are formedby crosslinking polymers such as polyacrylamide, xanthan, vinylpolymers, or lignosulfonates. Such gels are injected into the formationwhere crosslinking reactions cause the gels to become relatively rigid,thus reducing permeability to flow through the treated zones.

In most applications of these processes, the region of the formationthat is affected by the treatment is restricted to near the wellborebecause of cost and the reaction time of the gelling agents. Once thetreatments are in place, the gels are relatively immobile. This can be adisadvantage because the injected fluid (for instance, water in awaterflood) eventually finds a path around the immobile gel, reducingits effectiveness. Better performance should be expected if the profilemodification agent could slowly move through the formation to plug offnewly created thief zones, penetrating significant distances frominjection or production wells.

McKay, in U.S. Pat. No. 5,350,014, discloses a method for producingheavy oil or bitumen from a formation undergoing thermal recovery.Production is achieved in the form of oil-in-water emulsions bycarefully maintaining the temperature profile of the swept zone above aminimum temperature. Emulsions generated by such control of thetemperature profile within the formation are taught to be useful forforming a barrier for plugging water-depleted thief zones in formationsbeing produced by thermal methods, including control of vertical coningof water. However, this method requires careful control of temperaturewithin the formation zone and, therefore, is useful only for thermalrecovery projects. Consequently, the method disclosed by McKay could notbe used for non-thermal (referred to as "cold flow") recovery of heavyoil.

Accordingly, there is a need for a method to produce an emulsion thatcan be made economically and is capable of performing under a wide rangeof formation conditions, including salinity, temperature, andpermeability.

SUMMARY OF INVENTION

According to the invention, there is provided a method for producing afluid having hydrocarbons from a subterranean formation havinghydrocarbons and formation solids, comprising:

(a) making a solids-stabilized emulsion having water, oil, andundissolved solids, said solids comprising particles selected from thegroup consisting of formation solid particles, nonformation solidparticles, and combinations thereof;

(b) contacting the formation with said emulsion; and

(c) producing said fluid from the formation using said emulsion.

Preferably, such solids are comprised of particles having at least someoleophilic character for making an oil-external emulsion or somehydrophilic character for making a water-external emulsion. Morepreferably, such particles will have an average particle sizemeasurement which is about 2 microns or less, such average particle sizemeasurement being the largest of each of three measurements taken alongthe x, y, and z axis of each such particle and said average beingdetermined using either a weight or number distribution of suchparticles in a representative sample of such solids. If desired, carbondioxide or another gas can be added to the emulsion to decrease theemulsion's viscosity.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention and its advantages will be better understood byreferring to the following detailed description and the attacheddrawings in which:

FIG. 1 is a ternary diagram that illustrates some, but not all, of theparticle shapes that could be characteristic of the particles used tocompose the solids used to make a solids-stabilized emulsion;

FIG. 2 illustrates a plot of the viscosity of a solids-stabilizedemulsion, under a shear rate of 75 sec⁻¹ versus the emulsion'spercentage water content by volume;

FIG. 3 illustrates a plot of the viscosity of a solids-stabilizedemulsion with 58% water content by volume versus shear rate, in sec⁻¹ ;

FIG. 4 illustrates a plot of water cut, in volume percent, in fluidproduced from a laboratory core test versus total solids-stabilizedemulsion injected, in pore volumes;

FIG. 5 illustrates a plot of the average water saturation, in percentpore volume, in a laboratory core test versus total volume ofsolids-stabilized emulsion injected, in pore volumes;

FIG. 6 illustrates a plot of concentration of two different tracersproduced from a laboratory core test, bromide for tracing water that isa part of an injected solids-stabilized emulsion and dichlorobenzene fortracing oil that is part of an injected solids-stabilized emulsionversus total volume of solids-stabilized emulsion injected, in porevolumes;

FIG. 7 illustrates a plot of pressure drop over a laboratory core test,in pounds per square inch, versus total volume of solids-stabilizedemulsion injected, in pore volumes;

FIG. 8 illustrates a plot of three different measures of oil productionfrom a laboratory core test as a percentage of original oil in place(OOIP) versus total volume of solids-stabilized emulsion injected, inpore volumes; and

FIG. 9 illustrates a plot of the viscosity of a solids-stabilizedemulsion containing 60 volume percent water as a function of theconcentration of carbon dioxide dissolved in the emulsion.

The invention will be described in connection with its preferredembodiments. However, to the extent that the following detaileddescription is specific to a particular embodiment or a particular useof the invention, this is intended to be illustrative only, and is notto be construed as limiting the scope of the invention. On the contrary,it is intended to cover all alternatives, modifications, and equivalentswhich are included within the spirit and scope of the invention, asdefined by the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

A "solids-stabilized" emulsion made with particles comprising fine,solid particles is essential to practicing the invention more fullydescribed below. Solids-stabilized emulsion means that solid particlesare the primary means, but not necessarily the only means, by which thefilms surrounding the internal phase droplets of an emulsion aremaintained in a stable state under formation conditions for a sufficienttime to use an emulsion as intended (e.g., enhance rate and/or amount ofhydrocarbon production from a formation). Such solid particles areresistant to the chemical reactions that tend to deactivate surfactants,thereby causing de-stabilization or breaking of the emulsion.Consequently, solids-stabilized emulsions are stable over a wide rangeof formation water salinity.

Also, the term "solid", as used herein, means a substance in its mosthighly concentrated form, i.e., the atoms or molecules comprising thesubstance are more closely packed with one another relative to theliquid or gaseous states of the substance either under formation ornonformation conditions. Some substances that qualify as a solid underthe preceding definition, such as polymers or certain ceramic materialsincluding, without limitation, glass or porcelain, are often classifiedunder a rigorous material science definition as highly viscous liquidsbecause they are amorphous (i.e., lacking a crystalline structure).However, such substances are intended to fall within the meaning of theterm "solid", as used herein, despite their more rigorous classificationas "liquids".

Also, the source of the solids used for making a solids-stabilizedemulsion may be indigenous to the formation where such emulsion is used,hereinafter known as formation solids, or may be obtained external tothe formation, whether taken from another formation, mined, orsynthesized, hereinafter known as nonformation solids. In certaininstances, in fact, both formation and nonformation solids may becompositionally similar, but simply derived from different sources.

The particles composing the solids used for making the solids-stabilizedemulsions disclosed herein can have a wide range of chemicalcompositions, shapes, and sizes. The solid particles, however, shouldhave certain physical and chemical properties.

First, the solid particles should have at least some oleophiliccharacter for making an oil-external emulsion or some hydrophiliccharacter for making a water-external emulsion. Such character isimportant for ensuring that the particles can be properly wetted by theexternal continuous phase, whether oil, water or some other solvent,that holds the internal, discontinuous phase. The appropriate oleophilicor hydrophilic character may be an inherent characteristic of the solidparticles or either enhanced or acquired by treatment of the particles.The solid particles can be comprised of substances including, withoutlimitation, clays, quartz, feldspar, gypsum, metal sulfides, metalsulfates, metal oxides, coal dust, asphaltenes, or polymers. Preferably,however, the particles comprise at least about 5% by weight of an ionicand nonorganic substance, where an organic substance, as used herein,means a substance consisting of at least carbon and hydrogen atoms.

Second, the solid particles must remain undissolved in either the wateror hydrocarbon phase under formation conditions, but have appropriatecharge distribution for stabilizing an interfacial film between theinternal droplet phase, preferably water but alternatively oil, and theexternal continuous phase, preferably oil but alternatively water, tomake either a solids-stabilized oil-external emulsion or water-externalemulsion, respectively.

Third, the actual individual particle size should be sufficiently smallto provide adequate surface area coverage of the internal droplet phase.Particle size can be measured by a wide array of particle sizeanalytical techniques, including laser light scattering, mesh screenclassification, Coulter counting method, and settling velocity (whichuses Stokes law to convert a solid sample's settling velocity in a fluidto an average particle size). However, each of these techniques producesan "effective" particle diameter, which is the result that would havebeen produced by a corresponding test sample comprised of particles witha spherical shape. Consequently, a particle's effective diameter becomesa less accurate approximation of its true size as the particle's shapedeviates further from a spherical shape. In most instances, however,particles are often irregular and nonuniform in shape.

Without intending to limit the scope of the invention, FIG. 1illustrates this point with a ternary diagram, 114, having threefundamental shape groups. The first group is a plate or pie shape, 102and 104; the second is a bar or cylinder shape, 106 and 108, and thethird is a cube or sphere shape, 110 and 112. Typically, particlescomposing the solids used for making a solids-stabilized emulsiondisclosed herein will have some composite irregular shape that issomewhere between the two or three basic shape groups illustrated internary diagram, 114. Accordingly, the size of particles composing suchsolids are preferably determined using a scanning probe microscopy (SPM)technique. One example of such a technique is atomic force microscopy.Digital Instruments of Santa Barbara, Calif. manufactures an atomicforce microscope (AFM) known as the Nanoscope Multimode™, which has beenused to characterize the average size and shape of some of the solidparticles used in the working examples disclosed below.

Using AFM or some other SPM technique the maximum dimensions of aparticle along its x, y, and z axes can be determined. Therefore, unlessreference to an alternative particle size analysis method is otherwiseindicated, reference to a particle size will mean the largest of thethree dimensions measured along a particle's x, y, and z axis, asmeasured by a SPM technique. In the case of a perfect sphere, 112, orcube, 110, each dimension is equal while in the case of a particlehaving the shape of a pie, 104, or plate, 102, the thickness of theparticle, as measured along the z axis, is small relative to it length,x, and width y. The "average" particle size for a particular sample canbe determined by obtaining a sufficient number of measurements,preferably 50 or more, of the largest dimension for the array ofparticles being analyzed. The average size can be calculated using boththe weight average and number average methods. The number average methoduses the number of particles among the total measured having aparticular x, y, or z value, whichever value is largest. The weightaverage method uses the weight contribution of the respective particleshaving a particular x, y, or z value, whichever value is largest, amongthe total weight for all particles measured. The smallest of each ofthese two averages will be the relevant average used for practicing theinvention disclosed herein.

The solids-stabilized emulsion disclosed herein can be applied in avariety of applications within a formation to improve oil recovery,including, without limitation using such emulsions:

(a) as drive fluids to displace oils too viscous to be recoveredefficiently by waterflooding in non-thermal (or "cold flow") or thermalapplications;

(b) to fill high permeability formation zones for "profile modification"applications to improve subsequent waterflood performance, particularlyin formations containing lower viscosity oils (<100 cp); and

(c) to form effective horizontal barriers to vertical flow of water orgas to reduce coning of the water or gas to the oil producing zone of awell.

Solids-stabilized emulsions used for practicing the invention arepreferably generated above ground and injected as pre-mixed emulsion.Alternatively, a solids-stabilized emulsion can be generated "in situ"by injecting the requisite solid particles dispersed in water into aformation having hydrocarbons which can be used for making the emulsionin situ.

The oil used for making the solids-stabilized emulsion should contain asufficient amount of asphaltenes, polar hydrocarbons, or polar resins tohelp stabilize the solid particle-oil interaction. Preferably theemulsion's oil is comprised of oil previously produced from theformation where the emulsion is to be used, or, if the emulsion is madein-situ, the emulsion oil will be oil within the region of the formationwhere the emulsion is made. For example, the solids-stabilized emulsionsdisclosed herein are preferably used to recover moderately viscous orheavy oils (i.e., about 20 centipose to about 3,000 centipose). Suchoils, by nature of their composition, usually contain sufficientasphaltenes and polar hydrocarbons, which will help stabilize thesolids-stabilized emulsion. However, where the emulsion oil does notcontain a sufficient amount of asphaltenes or polar hydrocarbons, thesesubstances can be added with the solids to a concentration required forstabilizing the emulsion. The emulsification tests, described in detailbelow, can be used to determine whether any adjustment in the asphalteneor polar hydrocarbon concentration is required.

The water used for making the solids-stabilized emulsion should havesufficient ion concentration to keep the emulsion stable under formationconditions. Preferably, formation water is used to make the emulsion.However, fresh water could be used and the ion concentration adjusted asneeded for stabilizing the emulsion under formation conditions.

Also, as mentioned above, particle size is critical to making asolids-stabilized emulsion under formation conditions. The average solidparticle size, as defined above, should be about ten microns or less,but preferably about two microns or less, more preferably about onemicron or less and most preferably, 100 nanometers or less. Particleshape may also contribute to the emulsion's stability under formationconditions.

Other factors to consider in designing a solids-stabilized emulsioninclude, without limitation, the order in which the fluids are combinedand mixed to form the desired external and internal phases, the amountof mixing energy used to disperse droplets of the internal phase intothe external phase, and wetting properties of the solids, which affectsthe type of emulsion formed on mixing with the oil and water. Forexample, solids that are wetted by oil (i.e., oleophilic solids) willtend to form an oil-external emulsion, and solids that are wetted bywater (i.e., hydrophilic solids) will tend to form a water-externalemulsion. Because mixing procedures play a significant role in makingeffective solids-stabilized emulsions, some general principles relatedto making solids-stabilized emulsions, oil-external, water-external, andan emulsion containing gas, are provided below.

Making Oil-External Solids-Stabilized Emulsions

Solids used to form water-in-oil (i.e., oil-external) emulsions shouldpreferably have oleophilic or mixed-wettability wetting behavior. Suchsolids, if not naturally oil wetting or of mixed wettability, may bepre-contacted with the oil, or preconditioned, for a time periodsufficient to allow adsorption of polar hydrocarbons or asphaltenes ontotheir surfaces to render them partially or totally oleophilic prior totheir being mixed with final concentrations of oil and water. Othertreatments, such as reacting silanol groups on the surfaces of mineralsolids with chemicals such as organosilanes, or adsorption ofsurfactants on the solid surfaces, may be used to make the surfacesoleophilic before they are added to the oil and water.

A preferred method for generating such solids-stabilized water-in-oilemulsions is to first disperse the solids (preconditioned if necessary)in the oil phase, and then blend the said oil-solids mixture with waterand subject the blend to sufficient shearing/mixing energy to producewater droplets sufficiently small to remain dispersed and stabilized inthe oil.

The order and manner of mixing can have great effect on the propertiesof the resulting emulsion. For example, high-water-content oil-externalemulsions are best produced by adding the water to the oil rather thanadding oil to water. Water can be added to the oil to increase itsconcentration in small increments, with continuous shearing, until thetotal desired water content is reached. Such processing can producewater droplets having average diameters ranging from sub-micron toapproximately 30 microns, depending on the type and amount of shearingenergy input, the sizes and concentration of solid particles employed,the viscosity of the oil, the composition of polar and asphaltenehydrocarbons, and, to a lesser extent, the ionic composition of thewater employed. Other methods of mixing emulsions known to those skilledin the art may be employed so long as the resulting emulsion isoil-external, is stable under formation conditions, and has theappropriate viscosity.

Making Water-External Solids-Stabilized Emulsions

Solids used to form oil-in-water (i.e., water-external) emulsions shouldpreferably have hydrophilic wetting behavior, and preferably such solidsshould not have been exposed to hydrocarbons prior to use in stabilizingthe emulsion. A preferred method for generating such oil-in-wateremulsions is to first disperse the solids in the water, then add oil tothe mixture with sufficient continuous shearing/mixing energy to produceoil droplets dispersed and stabilized in the water phase. If necessaryto prevent forming oil-external emulsions, oil can be added to the waterin small portions, with continuous shearing, until the total desired oilcontent is reached. Such processing can produce oil droplets havingaverage diameters ranging from sub-micron to approximately 30 microns,depending on the type and amount of shearing energy input, the sizes andconcentration of solid particles employed, the viscosity of the oil, thecomposition of polar and asphaltene hydrocarbons, and, to a lesserextent, the ionic composition of the water employed. Other methods ofmixing emulsions known to those skilled in the art may be employed solong as the resulting emulsion is water-external, is stable underformation conditions, and has the desired viscosity.

General Principles Applicable to Both Oil-External and Water-ExternalEmulsions

Once the droplets are sheared to produce the desired size, the solidparticles arrange themselves at positions on the oil/water interface ina manner to prevent droplet coalescence, thus forming a stable emulsion.Emulsions generated in this manner are likely not thermodynamicallystable as would be true microemulsions, but they can remain stable formonths or years in a metastable state, and are sufficiently stable forpractical applications in recovering oil from formations.

Generating the emulsions above ground and then injecting them as eitherdrive fluids or as viscous banks to serve as flow barriers provides thebest method of controlling the ratio of oil, water, and solids in theemulsion and of insuring quality control on the achieved viscosity,droplet size distribution, etc. However, when mixing above ground is notpractical, water containing the dispersed solids can be injected intothe formation so that blending occurs in situ with formation oil. Insitu, shearing is naturally accomplished by flow of the fluids throughthe porous rocks.

Using Solids-Stabilized Oil-External and Water-External Emulsions in aFormation

While solids-stabilized emulsions can be used in a wide range ofapplications, one typical application is using such emulsions fordisplacing heavy oil (e.g., 325 cp) from a formation under ambientformation temperature (e.g., 140° F.). A solids-stabilized oil-externalemulsion applied in such a situation can yield an emulsion with amobility which is lower than that of the crude oil being displaced. Tominimize process cost, oil produced from the formation and water from alocal source (from underground or other source) and solids comprised ofclay particles having an average particle size less than 2 microns arepreferably used.

This invention is best practiced in formations with rock having anabsolute permeability that is sufficiently high so that the pore throatsare large enough to allow individual emulsion droplets to pass throughthe pores unimpeded. The lower limit on permeability is thus dependentnot only on the rock pore structure, but also on the droplet sizedistribution in the emulsion. For most applications, rock permeabilityis not expected to be a limiting factor. For example, many formationrocks containing heavy oil deposits have an absolute permeability offrom 2,000-15,000 millidarcies (md). Such rocks have pore throats withaverage diameters of from approximately 20-200 microns. Droplets sizesin emulsions injected into these rocks are likely to range in diameterfrom less than 1.0 microns to 15 microns, thus the droplets should notbe impeded in flow through such rocks. However, small droplet diametersare preferred to reduce possibility of trapping of the internal phase.

The lower limit of rock permeability to allow flow of a specificemulsion can be determined in laboratory tests by flowing said emulsionthrough a series of rocks of decreasing, but known, absolutepermeability. Procedures for conducting such core flow tests are easilyknown to those skilled in the art, but involve measuring pressure dropsacross the core at measured flow rates and determining whether theemulsion is trapped within the rock pores or passes unimpeded throughthe rock. An exact lower limit for application of such solids-stabilizedemulsions has not yet been established, but is believed to be below 1000md for emulsions having average droplet diameters of less thanapproximately 5 microns. Such core flood tests conducted in rockrepresentative of the target formation application are currently thebest method for determining whether the droplet size distribution of theemulsion is sufficiently small to allow emulsion flow without trappingof droplets at pore throats. If such core flood tests suggest thattrapping is occurring, applying additional shearing energy to furtherreduce average droplet size when formulating the emulsion may mitigateor avoid the problem. Additionally, a comparative core flood test usingan alternative solids type having a wettability that is more or lessoleophilic than the original solids type tested may be used to determineif increased stability during flow can be achieved. Accordingly, suchcomparative coreflood testing can be used to find the optimal solidstype, wettability and concentration.

Making and Using Solids-Stabilized Emulsions Containing Gas

Although the above disclosure describes how water, oil, and fine solidparticles can be used to make an emulsion useful for variousapplications within the formation for improving the recovery of oil, theuse of such fine solids to stabilize emulsions also extends to emulsionscontaining gas. For example, a gas consisting of either natural gas,carbon dioxide, nitrogen, flue gas, air, or other gas can beincorporated into such emulsions as described above in order to modifythe density of the emulsion, modify its viscosity, or to impart otherproperties beneficial for oil recovery.

Foams are special cases of emulsions containing very high gas contents,with internal gas bubbles stabilized by interfacial films containingwater, hydrocarbons, or other liquids, and stabilized by surfactants orother emulsifying agents. Often surfactants are used to create stablefilms for creating foams. In the current method, the stable films are tobe created by mixtures of oil, water, and fine solid particles, wherethe solid particles interacting with the oil and water stabilize thefoam film.

Additions of gas to the emulsion mixture at the time that the oil,water, and solids are blended, mixed, and sheared will permit generationof either an emulsion comprising primarily liquids with a lesserfraction of gas, or a foam comprising primarily gas, with onlysufficient liquids to form a stable foam, depending on the desiredproperties of the final mixture. An example use of this invention iswhen the density of a water-in-oil emulsion without included gas mightbe significantly greater than the density of oil to be displaced withinthe formation. If said emulsion without gas is injected to displace oil,gravity underride of the oil may occur because the emulsion would tendto sink below the oil to lower portions of the formation. However,sufficient gas can be included in the emulsion to cause the emulsiondensity under formation conditions to equal the density of the oil beingdisplaced, thus avoiding gravity underride.

There are other applications of such gas-containing emulsions or foamsstabilized by fine solids that will be apparent to those skilled in theart in view of the foregoing disclosure. Some examples are inclusion ofgas to reduce the viscosity of the injected emulsion, or inclusion ofcompressible gas to store energy for release as the emulsion encounterslower-pressure zones within the formation.

Adjusting the Emulsion Viscosity by Adding Gas

As noted above, gas may be added to an emulsion to adjust the emulsion'sviscosity. As illustrated in FIG. 2, an important property ofoil-external (i.e., water-in-oil) emulsions stabilized by solids is thatthe viscosity of the emulsion is always higher that the viscosity of thebase oil used to form the external phase. While FIG. 2 shows theviscosity of one oil-external emulsion measured at a shear rate of 75sec⁻¹ as a function of water content, the increase in viscosity as afunction of water content will be similar for other oil-externalemulsions. When the emulsion is used as a drive fluid to displace oilfrom a reservoir, the most efficient oil recovery is obtained when thewater content of the emulsion is high, for example 60 to 70 volumepercent water or higher. At such water contents, the viscosity of theemulsion may be approximately 10-fold to 20-fold higher than theviscosity of the oil used to form the emulsion. If the oil used to formthe emulsion has the same viscosity as the oil in the reservoir beingdisplaced by the emulsion flood, the emulsion viscosity will be higherthan needed for efficient flood performance.

To achieve efficient oil displacement in a reservoir flood, the mobilityof the emulsion drive fluid preferably should be equal to or less thanthe mobility of the oil being displaced. As noted above, mobility of thefluid may be defined as the ratio of fluid relative permeability tofluid viscosity. The relative permeability of the oil being displaced orof the emulsion containing a fixed water content will depend on the rockproperties such as lithology, pore size distribution, and wettability.These parameters are naturally governed by the fluid-rock system, andcannot normally be adjusted. However, the viscosity of an emulsion canbe adjusted to control its mobility. For normal ranges of oil relativepermeability and emulsion relative permeability, an emulsion viscosityof approximately two-fold to six-fold greater than the oil viscositywill produce a ratio of emulsion mobility/oil mobility of approximately1.0 or less. This will produce efficient oil displacement whilepermitting acceptable emulsion injectivity and flood life. An emulsionviscosity that is higher than needed to achieve this mobility ratio willstill provide very efficient oil displacement, but will also lead tohigher pumping costs and a longer flood life, both of which reduce theeconomic profitability of the process.

An efficient method for adjusting the viscosity of an oil-externalemulsion is to add a gas that is soluble in the oil phase (thecontinuous or external phase) of the emulsion and reduces its viscosity.Adding hydrocarbon gases such as methane, ethane, propane, butane, ornatural gas mixtures can produce reductions in oil viscosity. However,other gases such as carbon dioxide and sulfur dioxide can be especiallyefficient in reducing oil viscosity at only modest concentrations. Theemulsion viscosity therefore can be reduced by incorporating a gas intothe emulsion. Generally, a sufficient amount of gas should be added toreduce the emulsion's viscosity to less than about ten times (morepreferably, less than about six times) the viscosity of the oil beingrecovered. This can be achieved by saturating the emulsion with gas at apressure necessary to achieve the desired equilibrium concentrations inboth the oil and water phases of the emulsion.

FIG. 9 shows the viscosity of an emulsion initially containing 60 volumepercent water in oil as a function of dissolved carbon dioxideconcentration measured at 140° F. The emulsion was first prepared byblending water with a crude oil of 325 cp viscosity. Oleophilic fumedsilica (Aerosil® R972) was incorporated as the stabilizer at aconcentration of 0.5 g/L of emulsion. To generate the data plotted inFIG. 9, carbon dioxide gas was then added to the emulsion at a fixedpressure, as indicated, and the emulsion was mixed until the emulsionwas saturated with carbon dioxide at a temperature of 140° F. Theviscosity of the emulsion and the carbon dioxide concentration were thenmeasured. FIG. 9 shows that at a pressure of 700 psig the emulsioncontained 123 scf of carbon dioxide, and the emulsion viscosity wasreduced to 1100 cp from the initial viscosity of 5000 cp with nodissolved carbon dioxide. The ratio of emulsion viscosity/base oilviscosity was thus reduced from 15.4 to 3.4.

In the field, the carbon dioxide can be added to the oil and water priorto blending of the emulsion, or alternately the emulsion can be blendedprior to adding the carbon dioxide. Addition of carbon dioxide to theoil and water prior to blending the emulsion has the added benefit ofreducing the viscosity of fluids during blending, thus reducing neededmixing energy. Carbon dioxide can be added to the fluids using any of anumber of mechanical mixing methods known to those skilled in the art.For example, the carbon dioxide gas can be injected into the fluidupstream of a high-shear mixing device maintained at a pressure equal toor greater than the gas saturation pressure, or the carbon dioxide canbe mixed into the fluid in a counter-current absorption tower operatedat the desired pressure. Regardless of means used for mixing, thepressure within surface facilities needed to incorporate the desiredamount of carbon dioxide (e.g. approximately 400 psi to 1000 psi) willgenerally be much less than pressures the emulsion will subsequentlyencounter within injection lines, injection wells, or the oil reservoir.Therefore, the carbon dioxide will remain dissolved in the emulsion overmost or all of its useful lifetime, providing stable viscosityadjustment of the process.

While the above example illustrates the addition of carbon dioxide gasto the emulsion to reduce viscosity, it is understood that other gasesmay be used to adjust viscosity without departing from the true scope ofthe present invention. Also, while the viscosity reduction resultingfrom addition of a gas will likely be greatest where the emulsion is anoil-external emulsion, addition of a gas may also be beneficial inreducing the viscosity of a water-external emulsion. Accordingly, thepresent invention includes the addition of carbon dioxide or another gasto both oil-external and water-external emulsions to reduce theviscosity thereof.

Selection and Treatment of Candidate Solids

Enhanced emulsion stability will be achieved using solids that have: ahigh surface area/volume ratio, small mass and an average particle sizeof two microns or less, are attracted to polar or asphaltenehydrocarbons in the oil phase, and have surfaces that are eitherpartially or substantially oleophilic (for forming oil-externalemulsions) or hydrophilic (for forming water-external emulsions). Toform an oil-external emulsion, solids capable of meeting theserequirements include, without limitation, clays such as kaolinite orbentonites, or fumed silica treated to make the surfaces partially orsubstantially oleophilic.

Oleophilic fumed silicas, such as Aerosil® R972 or Aerosil® R974,manufactured by Degussa AG, CAB-O-SIL® TS-530 or CAB-O-SIL® TS-610manufactured by Cabot Corporation, consist of small spheres of fumedsilica that have been treated with organosilanes or organosilazanes tomake the surfaces oleophilic. These are effective solids for stabilizingmany crude oil emulsions. Such particles are extremely small, havingprimary particles consisting of spheres with diameters as small as about10-20 nm, although the primary particles interact to form largeraggregates. Concentrations of these silicas have been found to beeffective at concentrations of from approximately ≧0.5 g/L emulsion to≦20 g/L emulsion.

Natural clays can be mined and processed to make inexpensive solidshaving large ratios of surface area to mass. For example, particles ofkaolinite of approximately 1.0 micron or less in effective diameter, asmeasured by a laser light scattering technique, provide high surfacearea (approximately 10-20 m² /g). These clays normally have hydrophilicsurfaces. However, they can be mixed with crude oil at formationtemperature in a suitable vessel and maintained sufficiently long toallow high molecular weight polar hydrocarbons and asphaltenes to adsorbonto the clay surfaces and render them partially or substantiallyoleophilic. The mixture should be gently stirred or mixed to maintainthe particles in suspension and ensure good contact with the crude oil.A contact time of 24-72 hours or longer is usually sufficient to obtainoleophilic surfaces.

Bentonite clays, such as those mined in Wyoming, Ga., or other numerouslocations around the world, are particularly suited as stabilizers forcrude oil emulsions. As mined, these clays naturally consist ofaggregates of particles that can be dispersed in water and broken up byshearing into units having average particle sizes of 2 microns or less,as measured by a laser light scattering technique. However, each ofthese particles is a laminated unit containing approximately 100 layersof fundamental silicate layers of 1 nm thickness bonded together byinclusions of atoms such as calcium in the layers. By exchanging theatoms such as calcium by sodium or lithium (which are larger and havestrong attractions for water molecules in fresh water), and thenexposing the bentonite to fresh water, the bentonite can be broken intoindividual 1 nm-thick layers, called fundamental particles. Thechemistry of this delamination process is well known to those skilled inthe art of clay chemistry. Delamination occurs because the sodium orlithium ions, in fresh water, attract sufficient water molecules betweenthe layers (in a hydration process) that the layers are split apart intofundamental particles. This process can therefore be used to increasethe surface area per unit mass of bentonite by approximately 100 fold,providing extremely small (1 mn thick by 1 micron or less in width) andactive particles at low cost.

Also, solid particles used to make an emulsion can be treated to eitherdevelop or enhance their oleophilic or hydrophilic character. Forexample, delaminated bentonite particles can be precontacted with crudeoil at formation temperature to allow adsorption of polar hydrocarbonsand asphaltenes to render them partially or substantially oleophilic. Itshould be recognized that this is an example of one of many ways ofenhancing the adsorption of polar hydrocarbons onto the solids to renderthem oleophilic; other methods can be used without diverting from thetrue scope of the invention.

Testing Procedures

Phase Behavior Screening Tests

Oil produced from the target formation and source water (or syntheticwater prepared to duplicate the source water composition) are firsttested for emulsification effectiveness with various candidate solids.In this example screening test, 40 ml of crude oil preheated toformation temperature is first added to a 250 ml centrifuge tube. Then aweighed mass of clay particles (e.g. a clay such as bentonite,kaolinite, illite, or other clay having particle sizes ranging from lessthan 1 micron to 2 microns diameter), or alternatively, another type ofsub-micron-size solid such as fumed silica or coal dust, is added to theoil. The solids are then dispersed in the oil by inserting into the oilphase a laboratory blender capable of high shear (e.g. a Silverson ModelL4RT operated at full speed, or approximately 6000 rpm) and shearing theoil/solids mix for 2 minutes. The desired amount of water (preheated toformation temperature) is then added in increments with continuousshearing (for example, 60 ml of water can be added in three 20 mlportions over a 6 minute period to provide a total of 100 ml of testmixture). Then the mixture is sheared for 10 minutes, the tube iscapped, and the tube is placed in an oven whose temperature ismaintained at formation temperature.

The tube is maintained quiescent for 24 hours, and then the volume offree water separated is visually observed. The sample is thencentrifuged at 1000 rpm for 20 minutes (or at another speed and timejudged appropriate as a measure of emulsion stability), and the volumeof free excluded water is again measured. If no free water is observed,the sample is then centrifuged at 2000 rpm for an additional 10 minutes.Emulsions that do not break out free water under these test conditionsmay be judged good candidates for further testing in core floods.Samples showing superior stability can also be returned to the ovenwhere their stability in quiescent state can be observed as long asdesired (for example, over months).

For each candidate solid, a series of test emulsions should be generatedthat contain various ratios of water, oil, and solids concentrations todetermine the optimal concentrations of each. A typical concentration ofparticles needed to stabilize such emulsion might range from less than0.1 g/l emulsion to 20 g/l emulsion. The preferred water concentrationin the emulsion might range from 50%-90%, depending on the desiredemulsion viscosity and other considerations dictated by the formationapplication. Therefore, further screening tests may involve measurementof the emulsion viscosity. Additional tests may include measurement ofdroplet size distribution and average droplet size using microscopy orNMR methods. Preferred average droplet sizes will range from less than1.0 micron to 10 microns. If the solids originally added to the oil donot produce the desired droplet size, additional solids having adifferent size distribution and/or composition may be added to the oilto achieve the desired droplet size distribution. Adjusting the sizedistribution of solids utilized is but one of several parameters thatmay be adjusted to achieve the desired size distribution of droplets andwater content in the emulsion. The size ratio of average particlesize/average droplet diameter may range from about 0.001 to about 1,with the preferred ratio being less than about 0.5. The exact ratio willdepend on the size distribution of particles employed, the compositionof the solid particles employed, the level of shearing energy input,etc. A mixture of solids having differing compositions and/orwettabilities may also be employed. However, final choice of solidsconcentration, water content in the emulsion, emulsion phase state, anddroplet size should be based on tests conducted in core floods underformation conditions where the emulsion must remain stable while flowingthrough rock pores.

Core Flood Tests

Final selection of emulsion composition should be determined by tests inwhich candidate emulsions are injected into a core representative offormation rock and containing formation crude oil and brine (orsynthetic brine of composition equivalent to formation brine), allmaintained at formation temperatures. This is important because staticor centrifuge phase behavior tests do not subject the emulsions to theconstant low-level shear always present during flow through porousmedia, and centrifuge tests subject droplets to higher gravitationalforces than in porous media. Therefore, the core flood should preferablybe conducted at interstitial flow velocities representative of thoseanticipated in field applications (e.g. 1-3 ft/d) to test for phasestability of the emulsion and its ability to efficiently displace andrecover oil.

Core flood test procedures are well known to those skilled in the art,but the following summarizes tests used to evaluate oil displacementefficiency by emulsion flood. Irreducible (or connate) water saturationis first established by injecting crude oil into a core filled withformation brine. The core should be either actual preserved core fromthe formation or sand/rock thought to be representative of theformation. The core should then be allowed to equilibrate with the crudeoil to achieve correct rock wettability before the flood is initiated.The emulsion is then injected into the core at constant rate, andpressure gradients from the inlet to the outlet of the core, andoptionally over measured axial distances within the core, are measuredversus volume of emulsion injected. Volumes of water and oil producedare measured, and water and oil saturations within the core are computedas a function of the volume of emulsion injected.

Water-phase and oil-phase tracers may also be employed in various fluidsto assist in determining stability of the emulsion during flow. Primarymeasures of emulsion suitability are: oil recovery efficiency, amount ofseparation of water from the emulsion, and stable pressure gradientswithin the emulsion bank versus time and distance along the core.Optimization of the emulsion formulation can be achieved by comparingresults of core floods as a function of emulsion composition and methodof emulsion preparation. As known to those skilled in the art ofenhanced oil recovery, the optimal emulsion may be one judged to satisfyone or more subjective criteria such as maximizing oil recovery orminimizing drive bank mobility.

Making and Using an Oil-External Emulsion in the Field

The following description, disclosed without limitation and forillustrative purposes, is only one example of how the invention could bedeployed in the field. Other methods of making and usingsolids-stabilized emulsions in the field will become apparent to thoseskilled in the art in view of the following field applicationdescription. The desired concentration and type of oleophilic solids,determined from the laboratory screening tests, are added to a tank ofcrude oil produced preferably from the same formation. The tank andpiping are insulated to maintain the oil at or near the formationtemperature, and the solids are dispersed by continuously pumping oilthrough the tank to keep it stirred as solids are added. Other mixingarrangements can be used, as is readily apparent to those skilled in theart. This tank provides a concentrated dispersion of solids in crudeoil.

The emulsion can be made by blending the required volume ratio of crudeoil/solids concentrate with crude oil and water in either a continuousflow process through a series of one or more colloid mills (or throughother shearing devices readily known to those skilled in the art), orfluids can be recycled through a single shearing device from one storagetank to another in a batch mode. For example, if colloid mills are usedin a continuous (once-through) mode, the number of mills and theirrotation speed and gap setting can be adjusted to assist in producingwater droplets of the desired average diameter (preferably of about 5microns or less). Water can be added incrementally between each colloidmill to achieve the final target value without adverse phase inversion.The emulsion is then ready to be injected into the formation to displaceoil.

For such example application, if the oil viscosity is 325 cp, and thewater content of the emulsion is 80%, emulsion viscosity might beapproximately 3000 cp at 10 sec⁻¹. In certain instances, however,injectivity of such viscous emulsions may be lower than desired for aneconomic flood life. One method for increasing the injectivity of suchemulsions would be to heat the emulsion before injection so that theemulsion's viscosity is decreased in the near wellbore region. Away fromthe near wellbore region, the heated emulsion will cool to formationtemperature and the target viscosity will be achieved. Therefore, anefficient displacement of the heavy oil can be achieved, either with orwithout heating the emulsion, as appropriate. The final water saturationin well-swept zones of the formation might be about 80%, or the same asthe concentration of water in the injected emulsion. Therefore, underthe best mode of operation the injected emulsion should achieve analmost piston-like displacement of oil ahead of the emulsion because ofits significantly lower mobility compared to the oil. Under theseconditions, the emulsion, being very viscous and oil-external andtherefore more similar in relative permeability behavior to oil than towater, achieves a final oil saturation that is less than wouldultimately be realized in a waterflood, but at significantly less volumeinjected. For these formation conditions, a pattern waterflood might beexpected to recover 20% or less of the oil in place after 1.0 porevolume injection, while the net recovery of oil by the emulsion floodcould exceed 50% of original oil in place, or almost triple thewaterflood recovery.

Evaluation of Solids-Stabilized Emulsions--Lab Examples

The following laboratory test was conducted to demonstrate theeffectiveness of a solids-stabilized emulsion as a drive fluid fordisplacing and recovering heavy oil from a formation. In this test, anoil-external emulsion stabilized by kaolinite clay particles having amedian particle size of about 2.2 microns as measured by a laser lightscattering technique, was prepared and injected into a core of formationsand containing a heavy oil of 325 cp viscosity at the formation testtemperature of 140° F.

Chemical tracers were added to the oil and water contained within theemulsion to allow identification of those components in the fluidsproduced from the core and their differentiation from resident oil andbrine in the core at the start of the test. Data also were collected tomeasure overall pressure drop, oil recovery, water cut in the producedfluid, and average fluid saturations within the core, all as functionsof the volume of emulsion injected.

Unconsolidated sand obtained from extracted cores taken from a heavy oilformation was used to prepare a core test specimen. The core wasprepared by first filling a lead-sleeved core holder with the sand. Wirescreens were placed at the inlet and outlet of the core to retain thesand, and the outer length of the assembly was then wrapped with plasticfilm and aluminum foil, and then placed within a rubber sleeve in thesame manner as is commonly used to prepare unconsolidated sand cores forflooding. This core assembly was then placed in a triaxial core holder,and an overburden stress of 1800 psi was placed on the core to simulatetypical formation overburden conditions. Pressure transducers were usedto measure the overall pressure drop across the core. The core holderwas then placed inside an oven maintained at a constant formationtemperature of 140° F. All subsequent flooding operations were thenconducted at this temperature, including preparation and storing of theemulsion. Table 1 summarizes pertinent properties measured for the core.

                  TABLB 1    ______________________________________    Core Property         Measured Value    ______________________________________    Permeability to oil at S.sub.wi                          3,440 md    Porosity              27.9%    S.sub.wi  (irreducible water saturation)                          20.1% pv    Core length           16.1 cm    Core cross-sectional area                          11.4 cm.sup.2    core pore volume (pv) 51.2 cc    Net overburden stress 1,800 psi    ______________________________________

A brine was prepared by adding sodium chloride and potassium chloride todistilled water to provide the concentrations shown in Table 2. Thisbrine was used to saturate the core and to formulate the emulsion to beinjected.

                  TABLE 2    ______________________________________                     Concentration    Component        (mg/kg of brine)    ______________________________________    K.sup.+  ion     5,244    Na.sup.+  ion    7,867    Cl.sup.-         16,888    total dissolved solids                     30,000    ______________________________________

To prepare the core for the test flood, a vacuum was pulled on the core,and then brine was flowed into the core to achieve 100% watersaturation. A heavy oil of 325 cp viscosity was then injected into thecore at a rate 2 cc/min. to establish an irreducible (connate) watersaturation (S_(wi)) of 20.1% pv (pore volume). This establishedconditions representative of the initial conditions in the formationprior to injection of any fluid.

Fine mineral particles were added to oil to be emulsified to allow thesolid particles to become oil wet prior to being blended with water.Addition of solids to the oil before adding water is preferable if awater-in-oil emulsion is desired. First, fine mineral particlesidentified here as "field mix" and consisting primarily of kaoliniteclay (>90%), with minor portions of chlorite, sylvite, and quartz wereadded to a heavy crude oil of 325 cp viscosity. A laser particle sizeinstrument was used to analyze the particle size distribution of thesolids added to the oil. Results showed that the mean particle size wasabout 3.2 microns, the median size was about 2.2 microns, with at least40% of the particles having an effective diameter of 2 microns or less.However, this instrument could not measure particles below about 0.8microns in effective particle diameter, and thus likely underestimatesthe number of particles having sizes less than 1 micron.

The total amount of "field mix" mineral solids added to the oil wasapproximately 10 g/liter oil; however, this was considerably in excessof the amount required for efficient emulsification, and the oil wascentrifuged at 3000 rpm at 140° F. for approximately 18 hours to removethe excess. Approximately 90% of the solids were removed bycentrifugation. Tests showed that this centrifuged oil readilyemulsified with water, and still contained sufficient mineral fines forefficient emulsification. To prove that the mineral fines were indeedthe emulsifying agent, a sample of the centrifuged oil was then filteredin an in-line filter having a nominal pore size rating of 0.4 microns.However, this filter likely removed particles of sizes smaller thanabout 0.4 microns that became trapped by the filter cake. An analysis ofthe filtered material by scanning electron microscope showed that itconsisted almost entirely of mineral fines, so no significant amount ofany hydrocarbon component was removed. The filtered oil would notemulsify with water. However, re-adding mineral fines to the filteredoil restored its ability to readily emulsify.

Further tests showed that other minerals having an average particle sizeof about 2 microns or less (and preferably 1 micron or less), wouldreadily emulsify the filtered oil if the solids were preconditioned incrude oil for >24 hours to make them oleophilic. For example, a totallydifferent sample of purified kaolinite clay, identified as KGa-1,obtained from the Source Clay Repository of the Clay Mineral Society,with a mean particle size of about 1.6 microns, a median size of about1.6 microns, and with at least 80% of the particles having a size of 2microns of less (as measured by laser particle size analysis), was foundto readily cause the filtered oil to incorporate 60% water in anoil-external emulsion at a concentration of 0.5 g/L oil. Oleophilicfumed silica (Cabot CAB-O-SIL TS-530) added to the filtered oil at aconcentration of 50 g/L of oil formed oil-external emulsions containing60% water. Another test showed that bentonite clay subdivided intofundamental 1 nm layers and preconditioned by precipitation of polars(using the pentane precipitation method described above) added to theoil at a concentration of 4.7 g/L oil readily formed oil-externalemulsions containing 60% water.

To generate the emulsion tested in the core flood, approximately 400 ccof the crude oil with added "field mix" mineral fines was placed in abeaker with 600 cc of the brine shown in Table 1, and the mix wassheared until a uniform emulsion was formed in which all the water wasemulsified inside an oil-external phase. About 5-10 minutes of shearingwith a Silverson L4RT was sufficient. Observation of samples of theemulsion under a microscope showed that it contained stabilized waterdroplets ranging in diameter from approximately 1-30 microns or less.Droplets smaller than the visual resolution of the microscope may havebeen present but not detectable. Samples of the prepared emulsion weremaintained in quiescent glass tubes at 140° F. for periods of from daysto months to observe stability; no significant amount of excess watercould be observed to separate, so the emulsions were stable. Theseemulsions also did not reject free water when subjected to centrifugingfor 20 minutes at 1000 rpm and 10 minutes at 2000 rpm. FIG. 2 shows theviscosity of test emulsions at a shear rate of 75 sec⁻¹ versus watercontent. FIG. 3 shows the viscosity of the selected emulsion containing58% water by volume versus shear rate.

To conduct the coreflood test, emulsion was pumped into the core at arate of 0.213 ml/min. using a Ruska pump. Effluent from the core wascollected in approximately 5 ml increments in test tubes contained in anautomated fraction collector. Oil and water content in the each fractionwas determined gravimetrically using an analytical procedure based ondilution of the sample with toluene to break any emulsion present,followed by separation of hydrocarbon and water phases. Samples of theoil and separated brine phases were analyzed by ion and electron capturechromatography to determine emulsion tracer concentrations for eachincremental fraction of production. A concentration of 523 ppm ofdichlorobenzene (DCB) in the oil phase of the emulsion and aconcentration of 1000 ppm of bromide ion (from KBr) in the water phaseof the emulsion were used as tracers. Table 3 summarizes pertinent datafor the emulsion flood.

                  TABLE 3    ______________________________________    Data for the Emulsion Flood    Property            Value    ______________________________________    Fraction of water in emulsion                        58% by volume    Flood injection rate                        0.215 ml/min.    Flood interstitial velocity                        97.5 cm/day (3.2 ft/day)    Oil viscosity at 140° F.                        325 cp    Brine viscosity at 140° F.                        0.485 cp    Oil density at 140° F.                        0.93 g/ml    Brine density at 140° F.                        1.018 g/ml    Emulsion viscosity @ 75.sup.-1  sec                        2200 cp    ______________________________________

FIG. 4 shows the water cut in the fluid produced from the core as afunction of total fluid (i.e., solids-stabilized emulsion) injected.FIG. 5 shows the average water saturation in the core versus volume ofemulsion injected. FIG. 6 shows the ratio of tracer concentration in thecore effluent, C, to the initial concentration of tracer in the emulsionwhen first injected into the core, C_(o) (i.e., normalized tracerconcentration), versus the total amount of emulsion fluid injected inthe core, expressed in pore volumes. One plot represents the tracerconcentration ratio for bromide in the water phase of the injectedemulsion, while the second plot represents the tracer concentrationratio for dichlorobenzene ("DCB") in the oil phase of the injectedemulsion. FIG. 7 shows the pressure drop across the core versus thetotal amount of emulsion fluid injected in the core, expressed in porevolumes. FIG. 6 indicates that a bromide tracer concentration of 0.5 wasobserved after 1.0 pore volume of emulsion was injected, while a tracerconcentration of 0.5 was observed for the DCB at 1.17 pore volumesinjected. Thus, on average, the water in the emulsion broke throughafter 1.0 pore volume injected, and oil in the emulsion broke throughafter 1.17 pore volumes injected. These tracer results and thecorresponding pressure drop results in FIG. 7 indicate good emulsionstability and excellent mobility control with no trapping or loss ofviscosity.

FIG. 8 provides three measures of oil production from the core. The"total oil produced" includes all oil produced. The curve identified as"original in situ oil" shows production of oil originally in the coreprior to injection, as determined by the concentration of the emulsionoil tracer in the produced fluid. The net oil recovered is computed asthe difference between the total oil produced less the amount of oilinjected in the emulsion, and is of greatest interest in evaluating costeffectiveness of the process.

Net oil recovered at 1.0 pore volume injected is approximately 40% ofthe OOIP (oil originally in place). Waterflood oil recovery in similarcores for this oil ranged from 10.4% OOIP to 18.8% OOIP, so net oilrecovery using the solids-stabilized emulsion was 2.1 to 3.8 times moreeffective. Displacement of the original oil in situ oil was almostcomplete even at only 1.0 pore volume injected, illustrating theeffective mobility control achieved.

This test was conducted to demonstrate that the solids-stabilizedwater-in-oil emulsions move through the formation rock and efficientlydisplace the heavy oil. As indicated above, the tested solids-stabilizedemulsion exhibited good emulsion stability and excellent mobilitycontrol under the laboratory simulated formation conditions. Further,while this laboratory evaluation oil recovery would be economic and muchimproved over waterflooding, the emulsion utilized in this flood was notoptimized for oil recovery. Use of an emulsion with a water content of80% would likely realize a net oil recovery of 70% of OOIP at 1.0 porevolume injected. Further, as apparent to those skilled in the art, thesize of emulsion bank injected is a parameter that can be used toincrease net oil recovery. For example, water could be injected after a1.0 pore volume bank of emulsion, further increasing net oil recovery at2.5 pore volumes total injection. The injected emulsion bank size andemulsion water content are parameters to be selected based on economicoptimization for a specific field application.

The preferred embodiments of practicing the invention have beendescribed. It should be understood that the foregoing is illustrativeonly and that other means and techniques can be employed withoutdeparting from the true scope of the invention claimed herein.

What I claim is:
 1. A solids-stabilized emulsion for use in recoveringhydrocarbons from a subterranean formation, said emulsion comprising:(a)a first liquid; (b) droplets of a second liquid suspended in said firstliquid; (c) solid particles which are insoluble in both said firstliquid and said second liquid at the conditions of said subterraneanformation; and (d) a sufficient amount of a gas to reduce the viscosityof said solids-stabilized emulsion to less than about ten times theviscosity of said hydrocarbons.
 2. The solids-stabilized emulsion ofclaim 1, wherein said solids-stabilized emulsion contains sufficient gasto increase the mobility of said solids-stabilized emulsion to a pointapproximately equal to, but not greater than, the mobility of saidhydrocarbons.
 3. The solids-stabilized emulsion of claim 1, wherein saidgas is a hydrocarbon gas.
 4. The solids-stabilized emulsion of claim 1,wherein said gas is carbon dioxide.
 5. The solids-stabilized emulsion ofclaim 1, wherein said first liquid is oil, said second liquid is water,and said solid particles are at least partially oleophilic.
 6. Thesolids-stabilized emulsion of claim 5, wherein water comprises at leastsixty volume percent of said solids-stabilized emulsion.
 7. Thesolids-stabilized emulsion of claim 1, wherein said first liquid iswater, said second liquid is oil, and said solid particles are at leastpartially hydrophilic.
 8. The solids-stabilized emulsion of claim 1,wherein said solid particles are selected from the group consisting ofclays, quartz, feldspar, gypsum, coal dust, asphaltenes, and polymers.9. The solids-stabilized emulsion of claim 1, wherein said solidparticles comprise fundamental particles of bentonite clays.
 10. Thesolids-stabilized emulsion of claim 1, wherein said solid particlescomprise particles of kaolinite clays.
 11. The solids-stabilizedemulsion of claim 1, wherein said solid particles comprise fumed silica.12. The solids-stabilized emulsion of claim 1, wherein said solidparticles have an average particle size of less than about 10 microns.13. A method for making an emulsion for use in recovering hydrocarbonsfrom a subterranean formation, said method comprising the steps of:(a)selecting a first liquid and a second liquid for use in said emulsion;(b) selecting a type of solid particles to be used to stabilize saidemulsion, said solid particles being insoluble in both said first liquidand said second liquid at the conditions of said subterranean formation;(c) creating a mixture of said first liquid, said second liquid, andsaid solid particles; (d) shearing said mixture to produce an emulsionof droplets of said second liquid suspended in said first liquid,wherein said solid particles stabilize said emulsion by preventingcoalescence of said droplets of said second liquid; and (e) adding asufficient amount of a gas to said mixture to reduce the viscosity ofsaid emulsion to less than about ten times the viscosity of saidhydrocarbons.
 14. The method of claim 13, wherein said gas is added tosaid mixture prior to said step of shearing said mixture.
 15. The methodof claim 13, wherein said gas is added to said mixture after said stepof shearing said mixture.